Title

Presentation

Sunrun Inc. beats earnings expectations. Reported EPS is $0.2, expectations were $-0.22.

Operator: Good afternoon and welcome to Sunrun’s First Quarter Earnings Conference Call. Please note that this call is being recorded and that one hour has been allocated for the call, including the Q&A session. [Operator Instructions] We ask participants to limit themselves to one question and one follow-up question. I will now turn the call over to Patrick Jobin, Sunrun’s Investor Relations Officer.

Patrick Jobin: Thank you, Alicia. Before we begin, please note that certain remarks we will make on this call constitute forward-looking statements. Although we believe these statements reflect our best judgment based on factors currently known to us, actual results may differ materially and adversely. Please refer to the Company’s filings with the SEC for a more inclusive discussion of risks and other factors that may cause our actual results to differ from projections made in any forward-looking statements. Please also note these statements are being made as of today, and we disclaim any obligation to update or revise them. On the call today are Mary Powell, Sunrun’s CEO, Paul Dickson, Sunrun’s President and Chief Revenue Officer, and Danny Abajian, Sunrun’s CFO.

A presentation is available on Sunrun’s investor relations website, along with supplemental materials. An audio replay of today’s call, along with a copy of today’s prepared remarks and transcript including Q&A will be posted to Sunrun’s investor relations website shortly after the call. And now let me turn the call over to Mary.

Mary Powell: Thank you, Patrick, and thank you all for joining us today. In the first quarter, we exceeded our volume and cash generation targets in what is seasonally the slowest quarter of the year. We generated $56 million in cash, our fourth consecutive quarter of positive cash generation. We delivered market share gains and continued de-levering, paying down our parent debt by $27 million. We ended Q1 with $605 million in unrestricted cash, a $30 million increase from the prior quarter. At the same time, we are excited about the official announcement of our new product, Flex, which Paul will talk about shortly. It is a dynamic environment for tax policy and tariffs. These uncertainties make planning difficult and may require significant adjustments for the business.

Like many companies across the country, we are controlling what we can and are ready to adapt to changes that may occur. Sunrun has faced periods of major change over the last few years, and we used it as an opportunity to become even stronger. We believe the tariff outlook is manageable, and we will generate meaningful cash this year. We are delivering the best products for customers, underwriting volumes with strong unit margins, optimizing our routes to market, and driving cost discipline, including leveraging AI for innovation, creating significant operating efficiencies and quality enhancements. This has allowed us to gain considerable market share in recent periods and produce strong operating and financial results. Turning to an update on demand.

Demand remains strong. In Q1, total customer additions grew 6% compared to the prior year and, more meaningfully, our aggregate subscriber value grew 23% from last year, to more than $1.2 billion. This growth was supported by our higher value storage offerings and Flex. Customer additions with storage grew by over 46% from Q1 of last year, hitting a record-high 69% storage attachment rate. We are growing our share of consumers’ energy spend and have favorable tailwinds with further electrification, increasing grid instability and utility rate escalation. Americans want affordable and reliable energy. We provide a way for them to lock in predictable energy costs and reliability, with no money down. Demand for our offering is strong in good times and during periods of weakening consumer confidence, or even in a recession, as Americans look for ways to control what they can.

On Slide 5 you can see the strong volume growth we are achieving. Sunrun is now a multi-product company, primarily providing solar and storage systems, nearly quadrupling this business in the last two years. Demand for residential solar and storage is strong and the industry has only penetrated approximately 6% of households. Our approach has led us to gain considerable market share, as you can see on Slide 6. We have steadily increased our share to approximately 19% of new solar installations and about 45% of new storage installations across the country. Leading with a storage-first offering provides numerous financial benefits. Subscribers with storage have higher upfront margins, as we are providing a more sophisticated offering that provides additional value to customers, and because it is more complex to sell, design, install, and service.

Over time, storage systems also unlock additional recurring revenue streams as they represent valuable energy resources for the grid. While still a nascent business and small source of revenue today, this will grow significantly in the years ahead. Turning to updates on federal policy and the trade situation. We are encouraged that congressional offices understand the economic benefits of energy tax credits, especially given new electricity demand from trends like artificial intelligence. Interest in residential solar and storage is bi-partisan. Our 1 million customers and their representatives in Congress are politically diverse and they all want more affordable and reliable energy. A growing number of Republicans in Congress including 39 overall House members and four Senators have publicly expressed support for maintaining energy tax credits through various letters over the past few months.

Just last week an additional letter of support for maintaining the technology neutral credit 48(E) for the benefit of nuclear power was signed by 24 members. This credit is also the same technology neutral credit we utilize. We expect a range of draft proposals to be issued, possibly including some draconian scenarios, but they are expected to be moderated as negotiations progress. As a reminder, Republicans in the House can only lose three votes to pass legislation, and more than three dozen as well as four U.S. Senators have been advocating to maintain energy tax credits. We are actively working through scenario planning and corresponding actions if there are material changes. Actions could include ‘safe harboring’ with equipment purchases and paring back geographies.

In the past we have seen industry-wide customer acquisition costs decrease and end-consumer prices increase to absorb compression in margin from regulatory changes and we have a playbook to enact this. These are in addition to our ongoing efforts to drive further cost reductions and further monetize the value of our existing customer base. Shifting to the current tariff situation. Hardware costs represent about one-third of our total costs, and this cost will increase from tariffs. Near-term the effects are mitigated owing to the advance purchasing we did at the end of 2024. We are also shifting to use more domestically produced equipment, but supply is limited. Currently about half of our module supply and 100% of inverter and battery supply is sourced domestically, although with input components sourced globally.

We do not directly import any solar equipment from China, although producers in China are important for various upstream components used by our suppliers. Any adverse changes to tax and tariff policy, of course, will also impact utilities and create additional pricing headroom. Lastly, before I turn the call to Paul, I want to thank all of our Sunrun teams, and partners, that are clearly born to run, driving significant results for our customers and shareholders. This quarter, I also want to highlight our AI team. This team is driving enhanced efficiency and customer experience. As an example, one of our recent projects includes our system design tool. We have been able to unlock 30% higher efficiency in the design process improving turnaround times and accuracy, reducing costs, and increasing sales realization.

We are working on over a hundred AI initiatives across the company. A big shout-out to our Chief Technology Officer, Rachit, and the AI team leads: Chok, Edward, Lakshya, Marko, Parker, Terry, Victor and Yahia. Thank you so much. And with I will turn the call over to Paul to discuss Sunrun Flex.

Paul Dickson: Thanks Mary. One of the reasons we have been gaining significant market share, generating strong unit margins and producing cash is our innovative new product: Sunrun Flex. Flex is the most important financial product innovation the industry has seen since Sunrun introduced the residential Power Purchase Agreement in 2007. Currently, there are no solar + storage offerings, cash, loan or subscriptions that allow customers to plan for their growing energy needs in a flexible, affordable way. Home solar systems have historically been designed to either match a household’s current energy usage or be oversized in anticipation of future needs likely resulting in either unmet needs as energy usage increases or generating solar energy that is not used immediately.

Flex removes any uncertainty, offering a solution that fits families’ needs now and in the future. We do this by identifying the customer’s current energy usage and contracting with them for that amount of generation, like we always have. Then we ‘Flex’ up their system by adding additional panels and contract with the customer to buy that power when they use it. Over our history, we have observed homes that go solar on average increase their electrical consumption by 15% within the first year of getting solar. It’s also not uncommon for solar customers to adopt an electric vehicle, which drives up their energy consumption even more. This incremental energy consumption is typically coming from the utility at a high cost, or the customer needs to go through the hassle of getting an additional solar system installed.

Our offering allows customers to use more electricity in a locked-in affordable rate as they electrify their lifestyles. This means energy is ready for them as they want it, at a low rate. If they don’t use more electricity beyond their contracted minimum baseline, they don’t pay for it. Assuming 100,000 typical customers with Flex use just 15% more electricity, we would generate approximately $20 million per year in additional customer payments repeating every year. We are actively building out home specific insights and education to help our Flex customers make electrification decisions that fit their lifestyle, and enable them to tap into more Flex capacity which is available to them, this will result in many using significantly more than 15%.

We include only the baseline contracted amount in our contracted subscriber value, and the Flex upside revenues are additive to strong contracted net subscriber values from the product. Since we launched Flex in several pilot markets over the last few months, we have seen over 10,000, or over half of Flex-eligible customers select Flex over our non-Flex alternative. Since Flex systems are larger, we benefit from cost efficiencies from installing larger systems, and therefore can earn a similar margin to our standard product. If you assume the customers’ planned consumption increases, we will earn even higher returns from the recurring cash flows. Additionally, larger Flex systems are paired with more batteries, and the excess storage capacity creates an even more valuable grid resource, allowing these distributed batteries to benefit all ratepayers.

Sunrun is playing a different game, leading with storage, generating cash and innovating. Flex is only available through Sunrun. With that I’ll turn the call to Danny for the financial update and outlook.

Danny Abajian: Thank you, Paul. Turning first to Slide 12. As we discussed last quarter, we made modifications to our key operating metrics. We made these changes to simplify how we communicate our value creation activities. We now report both unit margins and aggregate value, starting from the topline gross value of subscribers, to present values of expected subscriber cash flows including non-contracted or upside revenues, present values including only contracted cash flows, and to margins that just reflect proceeds we expect to obtain from financing. We also made several other key modifications to methodologies. First, we moved to measuring subscriber values using a variable discount rate based on observed project-level capital costs each period, instead of using a fixed 6% discount rate.

Second, we are now reporting a precise advance rate each period to estimate proceeds, based on market terms, as opposed to reporting ranges. Third, we simplified how we calculate creation costs, including more costs such as R&D expenses along with tying the creation cost build-up directly to cash flow statement items. We did not remove any metrics we previously provided. We have provided a full reconciliation of these metrics in our posted materials and have provided recast historical metrics starting with the first quarter of 2023 for comparative purposes. Turning first to the unit-level results for the quarter on Slide 13. Subscriber Value increased to approximately $52,000, a 15% increase compared to the prior year, as we increased our storage attachment rate by 19 percentage points to 69%, grew our Flex deployments, and benefited from a 44% weighted average ITC level, an increase of 8 percentage points from Q1 of last year.

Subscriber value reflects a 7.5% discount rate this period. We were able to maintain cost discipline, with creation costs increasing only 7% from the prior year, a smaller increase than the 15% growth in subscriber value. Creation costs increased due to higher battery hardware and associated installation labor costs from the storage attachment rate increase, though labor productivity and fixed cost absorption offset a portion of these increases. This led to a 66% year-over-year growth in net subscriber value to $10,390. Consistent with prior years, the first quarter of the year is seasonally the lowest margin period of the year as we are ramping sales activities for the busier summer months and have worse fixed cost absorption from lower in-period installation activities.

Turning now to aggregate results on Slide 14. These results are the average unit margins multiplied by the number of units. First on the topline, aggregate subscriber value was $1.2 billion in the first quarter, a 23% increase from the prior year. Aggregate costs were $991 million, which includes all CapEx and asset-origination OpEx including overhead expenses. This resulted in net value creation of $246 million or approximately $1.09 per share. Excluding the expected present value from non-contracted or upside cash flows, contracted net value creation was $164 million, a 104% increase from last year, and about $0.72 per share. This level of value creation reflects a net margin of approximately 14% of contracted subscriber value. Slide 15 breaks down the unit-level economics and aggregate economics on a contracted-only basis, along with the main underlying drivers for the increases.

Turning now to Slide 16. Sunrun raises non-recourse capital against the value of the systems we originate each period from tax equity, which monetizes the tax credits and a share of cash flows, and asset-backed debt, along with receiving cash from subscribers opting for pre-paid leases and from governments and utilities under incentive programs. We estimate these upfront sources of cash will be approximately $1 billion for subscriber additions in Q1, representing approximately 87% of the aggregate contracted subscriber value, or what we call the advance rate. When we deduct our aggregate creation costs of $991 million, we are left with an expected upfront net value creation of approximately $12 million. This represents our estimate for the expected net cash to Sunrun from subscriber additions in the period after raising non-recourse capital and receiving upfront cash from subscribers and incentive programs.

It conservatively excludes any value from our equity position in the assets over time including potential asset refinancing proceeds and cash flows from non-contracted sources such as grid services, repowering or renewals, or upside from Flex electricity consumption above the contracted minimum. Actual realized proceeds in the quarter were just over $1 billion, with $256 million from tax equity, $755 million from non-recourse debt, and $53 million from customer prepayments and upfront incentives. Aggregate upfront proceeds differ from proceeds realized due to the former being an estimate for subscriber additions in the period, and the latter being the proceeds received against subscriber additions that may have occurred in a different period.

Cash generation, which reflects realized proceeds and is after other working capital changes and parent interest expense, was $56 million in Q1. We expect upfront net value creation and cash generation to correlate over time. These value and cash-based metrics clearly articulate how we create net value, finance our growth, and ultimately generate cash. Turning now to Slide 19 for a brief update on our capital markets activities. Sunrun’s industry-leading performance as an originator and servicer of residential solar and storage continues to provide deep access to attractively-priced capital. As of today, closed transactions and executed term sheets provide us with expected tax equity capacity to fund over 375 megawatts of projects for subscribers beyond what was deployed through the first quarter.

Thus far in 2025 we have added more than $1.3 billion in tax equity, resulting in this strong runway. We also have $819 million in unused commitments available in our non-recourse senior revolving warehouse loan to fund over 286 megawatts of projects for subscribers. Our strong debt capital runway allows us to be selective in timing term-out transactions. In January we priced a $629 million asset backed securitization at a yield of 6.35%. In March we priced a $369 million securitization at a similar yield of 6.36%. The March securitization was placed into the private credit market given strong interest from large alternative asset managers active in the space. The weighted average spread of the notes was 225 basis points, which is approximately 28 basis points higher than our January securitization.

The higher spread followed overall market movements in credit spreads for similarly rated credit. Similar to prior transactions, we raised additional capital in a subordinated non-recourse financing, which increased the cumulative advance rate to well above 80% net of all fees, as measured against the initial contracted subscriber value of the portfolio. Asset financing markets are open and healthy and there are an increasing number of investors, especially from private credit, who have done repeat transactions with us. We expect to continue executing both publicly-placed transactions and direct placements in the private credit markets. On the parent capital side, we continue to pay down parent recourse debt. During the first quarter, we repaid $27 million of borrowings under our working capital facility and repurchased a small amount of our 2026 convertible notes.

Since March of last year we have paid down recourse debt by $214 million. We have also increased our unrestricted cash balance by $118 million and grown net earning assets by $1.6 billion over this time period. We expect to pay down our recourse debt by $100 million or more in 2025. Aside from the $5.5 million outstanding of our 2026 convertible notes, we have no recourse debt maturities until March 2027. Over time we will explore further capital allocation options to maximize shareholder value, based on market conditions and our long-term outlook. Turning now to our outlook on Slide 20. For the full-year, we are introducing guidance for aggregate subscriber value and contracted net value creation. We expect aggregate subscriber value to be between $5.7 and $6 billion, representing 14% growth at the midpoint.

We expect contracted net value creation to be in a range of $650 million to $850 million, representing 9% growth at the midpoint. We are reiterating our cash generation guidance for the year of $200 million to $500 million. Underpinning this guidance are a couple things that have changed since our last call. We are seeing strong demand across channels, and as such now forecast subscriber additions will grow in the mid-single digits instead of our prior outlook of approximately flat for the year. This strength led to us beating our prior Q1 guidance for solar capacity installed and storage capacity installed. Offsetting these improving volume and unit margin fundamentals are the tariff developments. We expect the series of tariffs in place today to create cost headwinds of approximately $1,000 to $3,000 per subscriber in 2025, which is about 3% to 7% of creation costs.

This reflects tariff impacts being felt in the second half of the year and includes only partial mitigation measures, excluding any price increases and other cost reductions we may explore. These tariff impacts represent approximately $100 million to $200 million of potential variance within our guidance range. At current tariff levels, we are trending in the lower half of our cash generation guidance range, but if tariffs are substantially reduced, we would be trending in the upper half of the range. For the second quarter, we expect aggregate subscriber value to be approximately $1.3 billion to $1.375 billion, representing 21% growth at the midpoint, and contracted net value creation to be between $125 million and $200 million, representing 80% growth at the midpoint.

We expect cash generation to be between $50 million and $60 million. With that operator, let’s open the line for questions.

Operator: Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Brian Lee with Goldman Sachs. Please proceed.

Brian Lee: Hey, everyone. Good afternoon. Thanks for taking the questions. Lots of moving pieces here with the tariffs and some of the new guidance metrics. So maybe I’ll just start off with the sourcing strategy, you mentioned the 100% of the batteries are domestically sourced, but components may not be? And then you kind of outlined how different ranges of tariffs are going to push you to either the low or high end of the cash generation guidance. Can you also kind of help bridge – I mean when I look at the 2Q contracted net value creation, you’re talking about 80% growth year-on-year. And then for the full-year, it’s much more muted and about 9% even though the aggregate subscriber value is going to be up in the mid-teens. So is that just a representation of the second half impact of these tariffs? Or is there anything else in the middle in that bridge where the 2Q results look you’re getting a lot more accretion than what you’re getting for the rest of the year?

Danny Abajian: Yes. I think it’s generally the impact setting in, in the second half of the year, as we cycle through the equipment purchased safe harbor period where we discussed a full year worth of modules on the last call, half years’ worth of batteries. So as we cycle through all that, it’s materially picking up in the second half of the year as to the tariff impacts. So that’s kind of the general trend. Of course, that’s being met with strength on the volume side, continuing to grow. We’ve increased the ITC realization. We’ve grown volumes with higher value systems, and we continue to get some cost efficiencies through the business to offset some of the impact. But it is definitely back half weighted.

Brian Lee: Okay. That’s helpful. And then, I guess, if we were to assume the tariffs aren’t reduced, I guess, starting today or in April, can you kind of give us a sense of where your sourcing strategy is focused, how quickly you’re going to be able to pivot. And is this sort of gap between the subscriber value that you’re generating versus the net value that you’re achieving. Can you close that into the first, second quarter of 2026? Is it going to take longer? Because I just would assume that on growing scale. And some of the other tailwinds in the business that you presumably want to be creating more net value versus aggregate value at some point. Just wondering when you might get to that point and what the strategy is behind specifically the batteries to mitigate the tariff risk, if that isn’t reduced?

Danny Abajian: Yes, absolutely. And just like maybe relating it to the prior question. And I think also in the prepared remarks, any sort of price and go-to-market adjustments are not assumed, but the costs are assumed. So as we think about adjusting on the supply chain side, there’s also the topline adjustment on pricing and go-to-market sales commissions and other cost efficiencies could very much be part of the equation. But speaking to the supply chain side directly, a lot of the manufacturing has been increasingly been moving onshore. That’s a trend more related to the domestic content incentives that we have had. So that trend will presumably continue and offset some of the impacts as well. But I think also important to keep in mind that we may get substantial reductions in tariffs as well.

So we’re in a moment where we have been planning scenarios, I would say, on the go-to-market and pricing side. We haven’t acted upon any of that, but I think we stand ready to as soon as we have a bit more clarity.

Brian Lee: All right. Understood. Appreciate it. Thank you.

Operator: Thank you. Our next question comes from the line of Andrew Percoco with Morgan Stanley. Please proceed.

Andrew Percoco: Great. Thanks so much for taking our questions. Maybe just to pick up where you left off, Danny, on the pricing strategy. I think you guys are pretty clear that you’re seeing stronger-than-expected volume growth in the first quarter of the year. Just curious like what’s the sensitivity dynamic with the customers to those potential price increases have you engaged? Or how has your sales team engaged with customers since April 2, obviously, the first quarter was strong, but just curious how – if there has been any change in demand profile or consumer sentiment as your sales team has engaged in whether or not that might impact your pricing power here? Thank you.

Danny Abajian: Great. Yes, so I’ll start, and I think I’ll pass it to Paul to kind of hit more of the go-to-market aspects. I would say, it’s very much an exercise of taking all factors on balance. So interest rates, pricing, the direction of tax credits. There is a multivariable scenario planning that I think given a few weeks’ time, we’ll feel like moving into the second half of the year, we’ll have much better clarity looking at our cost structure where that’s trending. We have a lot of ambitions to continue to get cost efficiencies through the business, whether that’s the some of the AI initiatives, we set as examples, we’re continuing to build up scale as we sequentially grow volumes will also very much play a factor into all the modeling.

And as far as any adjustments, we don’t want to make adjustments prematurely. I think we see definitely headroom to make adjustments in markets. Certainly, as the whole industry will be bearing the problems associated with tariffs more uniformly. I think there’ll be pressure to make adjustments across industries. So we don’t think we’d be uncompetitive in doing so, but we just want to do it at moments where we feel like firm in those decisions from a longer term planning standpoint. But I’ll pass it over to Paul, if he wants to add anything.

Paul Dickson: Yes. Maybe the only thing I would add is in periods of clinical or economic like macro uncertainty, the Sunrun consumer offering plays very well. So as consumers are looking for price certainty and savings on utility costs and things like that, we see a lot of strong demand continue to persist. So we do see some of this uncertainty driving demand for the product.

Andrew Percoco: Okay. Understood. That’s super helpful. And maybe just a follow-up on the cash generation guidance. I know there’s a lot of moving pieces, a ton of uncertainty here. But I think you guys have previously committed to seeing growth in cash generation in 2026 over 2025. I know it’s probably increasingly difficult to do that in this period of time. But curious if you have any updated thoughts on that as it relates to 2026 cash generation? Thank you.

Danny Abajian: Yes. I think at this point, we feel like managing through the tariffs and looking at their back half impact, we could see positive cash generation in 2026. I think it’s way too premature to specify actual ranges. But as time goes by and we get into narrower planning scenarios, we’ll be able to share.

Andrew Percoco: Thanks so much.

Operator: Thank you. Our next question comes from the line of Moses Sutton with BNP Paribas. Please proceed.

Moses Sutton: Hi, good afternoon. I have a question on safe harbor. Do you plan on doing anything material in terms of safe harboring ahead of a possible IRA modification? Are you getting in front of that? And if not, why not, given the potential risk it poses to the business model if the ITC gets severely modified. I’d imagine you’d spend 5% of costs, I don’t know, through 2027, maybe via an equipment financing or some other arrangement. Any color there would be helpful. Thanks.

Danny Abajian: Sure. Yes. So the end-of-year activity was really us – twofold us looking at the transition from 48 to 48(E) credits. Of course, some price hedging, which is benefiting us well. We talked about the potential to do more in connection with some of the domestic content rules changing. I would say beyond that, it’s really a function of understanding what, if any, changes there will be and when they will set in, and those will establish the plan and the deadlines for executing more. I think in the meantime, generating cash continuing to have substantial unrestricted cash on hand, paying down debt will be the objectives. But I think that will all be supportive to also having the ability to safe harbor, if and when we get to those moments in time, which we think might arise in the future, but we certainly wouldn’t before with certainty knowing that we have to and what those financial benefits of doing so will be.

Moses Sutton: That’s helpful. And another one on the IRA, if transferability gets taken away, how would you consider the impact now that tax equity or at least vanilla tax equity is more competitive with utility scale market being 3x the size than it was three years ago?

Danny Abajian: Yes. So like others, we’ve heard some speculation around transferability getting discussed certainly too soon to know what will appear in drafts. I think it’s been made abundantly clear by industry as well, like what the benefit of transferability has been not just for us, but the adoption of a lot of renewable and clean technologies. So we think generally, there will be support for transferability. There was a 21 House Republicans specifically noted to support for continuation of transferability of tax credits, given what impact that’s had on the industry. And I think we’ve also been at the forefront of developing the tax credit transfer market, but we are also like recall we have historically been a very significant player in the traditional tax equity market as well, which has remained active and strong for us.

So any removal would create temporary shifts on how we source capital. But I think we feel like, ultimately, also the outcome will end up okay for the industry on that.

Moses Sutton: Thank you, Danny. I’ll take the rest offline.

Danny Abajian: Thank you.

Operator: Thank you. Our next question comes from the line of Maheep Mandloi with Mizuho. Please proceed.

Maheep Mandloi: Hey, good evening. Thanks for taking the question here. Just on the tariff portion, I think you kind of talked about that $100 million, $200 million impact. So that seems around 6% increase in prices required there? Just wanted to understand like how would that translate to actual PPA prices because there’s also some ITC, which could subsidize those tariff increases, right? So I’m just trying to think like how do we think about the price increases next year if tariffs don’t change here? Thanks.

Danny Abajian: Yes. I think you’ve got it. So it’s about a 3% to 7% of cost impact, again, back half weighted. So that was 3% to 7% for the year. A more substantial 10% potentially slightly higher if you take the second half realized impact. And that’s to be offset with – if it was entirely offset with pricing that would be the maximum magnitude though, as you correctly noted some of that will be offset by higher cost structure and therefore, higher fair market values. So some fraction of that 10% type number would be offset first by fair market values, and then the rest would need to get allocated towards – on the revenue side, higher pricing, on the cost side lower operating costs, lower customer acquisition costs. Anything else we can do on the efficiency side.

There maybe some go-to-market implications as well that might be slight, but we would have to look at that on a market-by-market level, products as we compare solar only with solar versus – solar and storage at the individual market level. There might be some go-to-market implications, but again, we’re narrowing the bands of uncertainty first and then actioning later, but we think we have a good well device playbook.

Maheep Mandloi: Appreciate that. And maybe just quickly on the Flex product. It seems pretty interesting here. Just want to understand like how does it impact the upfront cost. And then do you need any certain amounts of upgrades in the future or higher power draw to meet the same NPV or IRR compared to your current offerings?

Patrick Jobin: Yes, great question. So obviously, the product with larger systems has an increased equipment cost, but the efficiencies we gain associated with installing larger systems largely offsets. And in some cases, we even have superior upfront returns on the Flex product, absent the assumption of any utilization of the excess capacity. So similar to superior returns on its space as the base contracted product and then all upside as customers increase consumption, and we drive electrification.

Maheep Mandloi: Got it. Appreciate it. Thank you.

Operator: Thank you. Our next question comes from the line of Colin Rusch with Oppenheimer. Please proceed. Colin, your line is unmuted. We aren’t able to hear you. You may have yourself muted. All right. We may have lost him. Our next question comes from the line of Joseph Osha with Guggenheim Securities. Please proceed.

Joseph Osha: Hello. Can you hear me, everybody?

Mary Powell: Sure, can.

Joseph Osha: All right. Super. Two questions. First, understanding you can’t actually forecast cash generation next year. You have in the past provided some thoughts around the level of sensitivity in terms of cash generation relative to the ITC. And I’m wondering if you might be able to do that again. In particular, it’s interesting, if I look at Page 15 of your deck, I see 43.6%, squaring up against $164 million in the same period last year, 35%, $80 million. Can we perhaps try and draw some extrapolations from that analysis? Thank you. And then I have a follow-up.

Danny Abajian: Yes, absolutely. And Patrick appears to have moved into later in the presentation. So if you refer to Slide 27, the bottom of Slide 27 in the appendix, it’s 1 percentage point of weighted average ITC, realization is approximately $50 million. 25 basis points is – cost of capital is approximately $40 million. In the past, you’ve had storage attachment rate. That’s been a one point of storage attachment rate more in a single-digit number, but the two primary factors are there on the page, if you want to reference that.

Joseph Osha: Okay. And so that not to be a stick in the mud then, but that would imply all other things being equal, that a 30% ITC wipes out your free cash. Am I drawing that conclusion correctly, if I go back to 30%? Or can the company take some steps to mitigate that?

Danny Abajian: Yes. So all else equal, it’s 50 x 15. So that’s the right math. But there would certainly be plenty of action to offset as much of that as we could. So pricing, again, all the same factors, whether it’s tariffs or ITC level changes, pricing, customer acquisition costs. If we’re talking about a 45% level going to 30%, also substantial go-to-market implications.

Joseph Osha: Okay. Thank you. And then my second question are good friends that the CPUC Public Advocates Office have been busy, as I’m sure you know. I’m wondering, if you have any thoughts about how that situation might progress and specifically as it relates to the state funding net metering out of a different funding source? Thank you.

Mary Powell: Yes. Hey, Joe. Good to hear you, and thanks for the question. I mean, yes, as you would expect, we’re tracking closely and very active in the state house. Utility rates in California, you know have risen rapidly because of investments.

Danny Abajian: I look at that…

Mary Powell: Yes, exactly. So there’s definitely been some push under the agenda of affordability. And we were really pleased the other day that, again, the language that would have been very negative for our industry, for our customers and for our existing customers, was actually taken out of the bill. It was a very, very active opposition. So yes, we stay very engaged, and our customers stay very engaged as well as other advocates in the space.

Joseph Osha: And just to clarify for our listeners that it is true that the grandfathering or degrandfathering, I guess it is, has been taken out of the bill. Yes?

Mary Powell: Yes. 100%, yes. Sorry, I could have said that more specifically, yes.

Joseph Osha: Degrand, whatever that is. Okay. Thank you very much.

Operator: Thank you. Our next question comes from the line of Philip Shen with ROTH Capital Partners. Please proceed.

Philip Shen: Hi, thanks for taking my questions. I have a follow-up on the transferability question. If that is removed from the IRA. I think, Danny, you mentioned that it would be a temporary shift in how you source your capital. So I was wondering, if you could elaborate on that. So specifically, would you elect for the direct pay option? And then kind of work with some lenders for bridge financing. What are the levers that you might be able to pull to manage that transition? And how big of a concern do you think it might be? I know you emphasized that you’re still working with the bank partners that you’ve had, but I think 50% of the market is with transferability partners at this point. So there could be a bit of a hiccup. Just wondering, how you guys manage through that? Thanks.

Danny Abajian: Sure. Yes. So I think just at a high level, it’s very important to see the full balance of activity or the full balance of changes that result from the package, right? So if transferability were removed, it is a supply and demand-driven market. So you’d also have to look at what available supply of credits are also removed from the market based on changes to the IRA. So we don’t know where the market equilibrium will be on supply/demand. We’ll have to know that missing data point as well to be more fulsome in the response. So the comment about the shift in our approach really is nothing more complicated than we would be more – you would be reliant on the traditional tax equity market as opposed to some hybrid of the two as we are today.

Philip Shen: Okay. Thanks, Danny. And then on the tax equity, supply. In your remarks, you talked about having capacity to fund 375 megawatts beyond Q1. I think at the end of Q4, it’s 500 megawatts. Can you just give us an update on what the tax equity market is doing thus far? There’s been some changes in the market with TPOs, some are not doing as well as you know. And so with the uncertainty around the IRA and so forth, has pricing changed to any degree for you guys specifically, 375 is a decent amount – a very high amount for – on an absolute basis, but it might carry you guys about two quarters. And so just curious, how you expect tax equity funding to close in the coming quarters? Thanks.

Danny Abajian: Yes. So we’re well diversified against a – amongst like a large and increasingly growing buyer universe. We continue to close transactions. So we’re not – it’s not a relatively few number, especially with transferability in the mix. It’s not a relatively small number of transactions we’re doing in tax equity, its hybrid transactions, some of very large size within which we’re placing multiple tax credit transfers, and we continue to do that through quarters. So I think that continues to look good to us and continue to develop certainly as others in the market with available tax credits struggle and fail to deliver them. There is an aspect of a safety play with Sunrun who has a steady flow and is like proven to be reliable.

So in moments where the – on the buyer side, you have numerous options for where to acquire your credits, this sort of environment there could also be like if you will, like a flight-to-quality benefit that could be in our favor. But what we’d like to do is demonstrate to everyone who’s done transactions with us, how solid we are on the delivery so that they also repeat with us, and that’s been the track record as far back as we can go.

Philip Shen: Great. Thanks, Danny.

Operator: Thank you. Our next question comes from the line of Dylan Nassano with Wolfe Research. Please proceed.

Dylan Nassano: Hey, good afternoon. Thanks for taking my question. I just want to go back to the conversation around competition. You’ve shown the slides that you’re seeing market share actually start to tick up. And in the past, you’ve talked about kind of staying disciplined and not trying to solve for market share. So I guess, just can you walk us through like how are you accomplishing that? And any changes to kind of how you’re thinking about competition in light of the tariff impacts?

Paul Dickson: Yes. Great question. So we really view it as charting our own course in the industry right now. And we’ve talked in the past about the rates that other dealers pay and financing companies and things, but as we focus more on differentiating and innovating our product offering, we’re seeing more customers understand and realize the benefits of – I can get standard product from some finance company and a rep may make more or less, but I have a similar offering compared to a Flex offering, for example, where they get a bunch of extra capacity at a locked-in low rate that they can tap into for a similar contracted rate on the base amount. Things like that, things like leaning into storage and customers buying more on resiliency and understanding features and benefits, people are caring more about, the longevity of the company being around to service their assets and reviews, things like that.

So we’re really seeing all of the benefits of what we’ve been working to build here at Sunrun flow through in consumer demand and competing less on price and pay and focusing more on differentiation.

Dylan Nassano: Great, thanks. And then for my follow-up. So Danny, correct me if I’m wrong, but I think you’re actually running at pretty close to your targeted blended ITC level for the year. How should we think about that trending through the rest of the year? Is it – could it potentially go a little bit above what the target was for the year?

Danny Abajian: We’re still expecting a mid-40%, 45% number. So we cited the initial part of the year as being a little bit of a delayed ramp than we expected two quarters ago. I think we’ve hit – we’ve largely hit that ramp, and I think we’re generally expecting the flat line as we hit that 45% level and go through the rest of the year.

Dylan Nassano: Great. Thank you.

Operator: Thank you. Our next question comes from the line of Kashy Harrison with Piper Sandler. Please proceed with your question.

Kashy Harrison: Good afternoon. Thanks for taking the questions and congrats on the results. Maybe just a follow-up to Moses’ question earlier on safe harbor. So let’s say, there is a step down in the ITC coming to 30%, how many years do you think you would be able to safe harbor based on your discussions with your equipment suppliers, and what would be the plan to finance it?

Danny Abajian: Yes. So it is dependent on available supply, available capital. I think we – as we noted on the last call, the Q4 activity was about a year’s worth of modules, also six months of batteries. The reason for six months was available physical supply driven. There are other ways we could go longer than that, but there would be some limitations. Once you get out beyond the period of six months – six to 12 months, I think it gets – there are certain ways we could achieve it, but it gets more limited.

Kashy Harrison: Got it. I appreciate that color. And then – and maybe from a…

Danny Abajian: Just to follow on the thought. If it’s – as has been the case in the past, if it’s multiple step-down events over multiple years, then there are also multiple safe harbor events of shorter periods of time. So it’s not that – it’s not a one-and-done duration of six to 12 months if that’s the available supply. It’s a recycling over a number of years. So as the step-downs occur, yes, we will have stepped down. We will have delayed it, but we will also be carrying a higher level of realized ITC than competitors who were not able to safe harbor. So that would be a competitive advantage on the way down.

Kashy Harrison: Got it. I appreciate the thoughts there. And then maybe my follow-up, Danny, I think you flagged that the full impact of the tariffs would be closer to 10%, later in the year after you exhaust your current inventory? Is that correct? And is that – is the bulk of that really just coming from the batteries? And then maybe lastly, like – if we do see a situation where maybe the tariffs on batteries aren’t – sorry, from Chinese cells aren’t 150, maybe they’re 50%, for example, how should we think about the impact to your increased tariff costs that you flagged? Thank you.

Danny Abajian: Yes. We see it – so majority is right. So we see majority from battery costs. So I’d say a little more than half to be more specific. And that sort of magnitude would be driven by sales supplied from China, as you noted. So it would be the portion of battery costs that are cell-driven would be the math to do on the way down.

Kashy Harrison: Got it. Thank you.

Danny Abajian: There are other – like there are, in addition other components upstream, but that would be the biggest number.

Operator: Thank you. Our last question comes from the line of Ameet Thakkar with BMO Capital Markets. Please proceed.

Ameet Thakkar: Hi. Thanks for squeezing me in. Just, I guess, maybe a follow-up on Kashy’s question that the 10% increase, is that net of any price adjustments you’ve made on your end? Or is that the kind of the gross impact to you right now before any price increases? And I have one quick follow-up.

Danny Abajian: It’s gross.

Ameet Thakkar: Okay. Thanks. And then just coming back to California Assembly Bill 942. Just to kind of be clear, the sunsetting kind of provisions are all out, it’s not going from 10 to 20 years. Is that correct? And then they still have kept the provision where if a homeowner sells their system, then they would kind of lose the NEM 2.0 status. Is that correct? And how do you see that impacting your kind of estimates for renewal value? Thank you.

Mary Powell: Yes, you have it absolutely correct. Again, generally telling customers that you’re reneging on a promise doesn’t actually work. So yes, that language was killed. And the home transfer language is still in there, but it will be interesting to see if it lives to see final passage.

Ameet Thakkar: Thank you.

Operator: Thank you. That concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.